Enbridge Inc Q1 FY2022 Earnings Call

Welcome to the Enbridge Inc. First Quarter 2022 Financial Results Conference Call. My name is Justin, and I will be your operator for today's call. Please note that this conference is being recorded. I will now turn the call over to Jonathan Morgan, Senior Vice President, Capital Markets. Jonathan, you may begin.

Thank you. Good morning and welcome to the Enbridge Inc. first quarter 2022 earnings call. Joining me this morning are Al Monaco, President and Chief Executive Officer; Vern Yu, Executive Vice President and Chief Financial Officer; Colin Gruending, Executive Vice President, Liquids Pipelines; Cynthia Hansen, Executive Vice President, Gas Transmission and Midstream; Michele Harradence, Senior Vice President and President Gas Distribution Storage; and Matthew Akman, Senior Vice President, Strategy, Power and New Energy Technologies. As per usual, this call will be webcast and I encourage those listening on the phone to follow along on the supporting slides. We will try to keep the call to roughly one hour; and in order to answer as many questions as possible, we’ll be limiting the questions to one plus a single follow-up as necessary. We’ll be prioritizing questions from the investment community. So, if you are a member of the media, please direct your inquiries to our communications team, who will be happy to respond. As always, our Investor Relations team will be available following the call for any follow-up questions. And on to slide 2 where I’ll remind you that we will be referring to forward-looking information on today’s presentation and Q&A. By its nature, this information contains forecasts, assumptions and expectations about future outcomes, which are subject to the risks and uncertainties outlined here and discussed more fully in our public disclosure filings. We’ll also be referring to non-GAAP measures as summarized below. With that, I’ll turn it over to Al Monaco.

Good morning, everyone. To start, what you see here is the first of 80 turbines being installed at our 480-megawatt Saint Nazaire wind project off the West Coast, France. Just to give you a sense of the magnitude of this infrastructure, the towers are 170 meters in height, and each blade is about the same as the wingspan of an Airbus A380. So, it's a pretty exciting time in our Renewables business, and more on that later. First of all, recent events are very troubling, and we’re all very concerned for the people in Ukraine. Many of our staff have connections to the region, and we’re supporting them. What’s happening is also revealing a lot about global energy markets. So, I’ll start off with how we’re thinking about that followed by our business update, and Vern will cover our financial results and outlook. Before that, this slide captures our Q1 highlights. It’s been a good start to the year. All four businesses performed well, operating at or near capacity. That translated into strong Q1 numbers, and we’re on track to achieve our 2022 guidance. The balance sheet’s in good shape. Both S&P and Fitch reaffirmed our BBB high ratings. We’ve got $10 billion of projects in execution with $4 billion slated for service this year. So far in 2022, we’ve added another $1 billion to our project backlog that will support post-2024 growth. We’ll update you on two carbon capture opportunities we’re very excited about. More broadly, we’re seeing a pickup in customer infrastructure, especially LNG export. Recall, there’s $5 billion to $6 billion a year of conventional and low carbon opportunities enterprise-wide in the hopper. Those will go through our capital allocation filter, which Vern will also cover later on. So, on the energy markets. Coming into the year, we saw growing demand and underinvestment in supply move energy prices higher. The Russia-Ukraine war has worsened the demand-supply gap, obviously, but it’s also put energy back in the spotlight. Energy markets are at an inflection point and we’re in an energy crisis. There are three things that come out of this. Any way you look at it, global energy supply will need to increase to address national security risks, affordability, and reliability. That means we’ll now need an energy supply buffer and greater diversity of that supply to manage those risks. Europe’s heavy reliance on Russia is driving this, but the impacts are broader and global, regardless of when this war ends. Second is the energy transition. We’ll need to accelerate low-carbon investments as well to meet demand, achieve emissions goals, and as part of the security buffer. To make that happen, we’ll need to pick up the pace on proven ways to grow low-carbon fields, like RNG, hydrogen, and especially carbon capture. And that’ll mean leveraging existing transportation and storage infrastructure more quickly, like ours. It also means much more investment in natural gas to provide reliable, lower carbon base-load power and to enable renewables. Third, North America will play a much larger role in the global energy market. The North American energy advantage is even more evident today, with massive low-cost reserves and the technology to produce them with the lowest carbon intensity. And of the 10 largest global producers, Canada and the U.S. are number one and two on sustainability. You can see that with the ESG scores on this chart. North America will be the supplier of choice. You saw that already with the U.S. and EU announcement to work together, and Asian markets are also looking to secure long-term supply. The biggest opportunity in our view is natural gas exports, with the potential for over 30 Bcf a day. That’s more than triple last year. And, of course, crude exports are set to grow by 50%. All of this is very positive for infrastructure pointed at tidewater. Remember as well that the North American grid is integrated. So, growing global demand and export is upside for Canada and the U.S. What you see here is underpinned by strong energy demand. We’re going to need more supply of both conventional and low-carbon energy, and now, that’ll be needed faster. 80% of world demand comes from hard to abate industrial uses and heavy transport, and of course, petrochemical demand is growing. It’s also clear today that natural gas will be essential to meeting demand. Even before the crisis, Europe amended its taxonomy for clean energy to include natural gas. On low-carbon investments, $25 trillion will need to be invested, with renewables being the largest component along with RNG, hydrogen, and again, carbon capture. We are headed in the right direction on the tax credits in the Canadian government budget, incentivizing carbon capture, and there are U.S. proposals to expand 45Q. So, what does all this mean for our strategy? This slide recaps the two-pronged approach we outlined for you at Enbridge Day. Our strategy is to invest in both conventional and low-carbon energy, which makes even more sense today. On the conventional side, we’ll focus on optimizing throughput and modernizing our systems. On low-carbon, we’ll continue to align with the pace of transition and we’ll see over $4 billion of low-carbon opportunities through 2025. Finally, any new investment in conventional or low-carbon will need to meet our investment criteria. So, that will change. When you step back from all of this, we believe the two-pronged strategy approach makes even more sense today where energy security is back in the spotlight and where demands for conventional and low-carbon energy supplies will continue to rise. Now, to the business update and gas transmission. Very strong volumes with Texas Eastern hitting 16 of its top 25 peak days ever. We’re on track to put US$1.2 billion into service this year, that’s on top of the the US$2.4 billion last year. The lion's share of spending is on new compression or modernization more generally. Along with our solar self-power projects, we’re lowering emissions. For example, our current modernization program will take out 182,000 tons of CO2 per year. We’re also excited about more organic growth. We’ve got good optionality to support growing domestic demand. It’s clear that more capacity in the U.S. Northeast is needed to manage disruptions and peak demand. We all know what’s happening with global gas prices, but it’s not pretty for U.S. Northeast consumers either with gas prices at roughly 5 times Henry Hub. This situation screams for more infrastructure, especially given increased supply variability from offshore wind that’s coming and more displacement of coal, of course. We put phase one of our Appalachia to Market project into service last year and Phase 2 is in pre-construction. Building greenfield is tough these days, but these expansions are executable and cost-effective, and there’s more we can do. LNG exports are a big opportunity with momentum building across the U.S. Gulf and now more so in Western Canada. Our Texas Eastern System feeds LNG along the Gulf Coast. We supply four plants today with about 2 Bcf a day. We’ve locked up capacity agreements with three more LNG projects that could add up to 7 Bcf a day and over $2 billion of new investment. Plaquemines LNG is now fully contracted and likely moving ahead, which will drive $400 million on our Venice Extension project, not in the secured category yet, but we expect it to be shortly. Texas LNG and Rio Grande LNG are also progressing at a fast pace. In fact, earlier this week, we saw NextDecade granted a 15-year SPA with ENGIE to support Rio Grande, and we’re seeing good momentum with both projects potentially reaching FID later this year. And by the way, on Rio Grande, that could drive FID on our Rio Bravo Pipeline. Western Canada is another big growth region for us. Shifting fundamentals are bringing Western Canada to the forefront once again. You’ve got a world-class liquids-rich resource base that rivals the Marcellus and Haynesville, and operators have done a tremendous job unlocking reserves. We could see production grow by 50% for LNG export here and increased regional demand growth. With growing demand in Europe for U.S. LNG, Western Canada can step in to fill the gap. Proximity to Asian markets provides two to four weeks of reduced shipping time and lower emissions. LNG breakevens in Canada are roughly $6 to $8 an MMbtu, which rivals the U.S. Gulf Coast and looks very favorable compared to Asian LNG prices, somewhere in the order of $30 an MMbtu in Q1. LNG Canada is under construction, and Woodfibre is advancing early-stage construction activity. We’re the main conduit out of the Montney and Deep Basin. So, all of this bodes well for upstream expansion on our B.C. Pipeline System. On that note, we launched a binding open season today for 400 million cubic feet on T-North. That’ll be a $1 billion expansion. Woodfibre LNG is contracted on T-South with volumes currently flowing to the Pacific Northwest. Once they reach FID, we’ll need to create new capacity to replace volumes currently moving south. That expansion would be approximately $2.5 billion. Depending on Woodfibre’s FID timing, we’re targeting a binding open season on T-South for later this year. This might also require further upstream expansion on the T-North site. So, all of this is shaping up to be a big opportunity over several years, which goes to prove the value of pipe in the ground. Now, longer term, we also hold what could be two valuable pathways to the coast, the Pacific Trails and the Westcoast Connector corridors. We see these as low-cost options on the future of LNG exports. For either of these to move forward, we’ll need to see a clear path to execution with strong local community support and commercial underpinning. So, we have a way to go for those. Turning to liquids, Q1 Mainline throughput averaged 3 million barrels per day. Seasonally, we’ll see a more concentrated maintenance season in Q2 than we usually do, offset by stronger volumes in the back end of the year. But we remain on track for the full-year average utilization of 2.95 million barrels per day that we guided to in December. On Mainline tolling, healthy dialogues with shippers are ongoing. As you may recall, we shared our cost information, which was the precursor to negotiations. Our sense is that shippers would prefer another incentive tolling deal. Of course, that model worked well for 27 years and aligned us with the shippers. But, as we’ve said, we’ll need to see an appropriate return, given the risks we manage under that model. Given it’s often challenging to reach a consensus, we’re preparing a cost of service filing, which is a very good alternative for us. The schedule is the same as we showed you last time, where we expect to have a new tolling construct in place in 2023. Now, more broadly on liquids and how it fits within the shifting energy landscape I talked about earlier. Our scale and access to the best markets provide a ton of optionality and value for our customers. Our focus is adding highly executable capacity to the Midwest and the Gulf. In total, we’ve got roughly 400,000 barrels per day of egress opportunity on the Mainline and Express. We’re also developing a new Gulf Coast path by Pony Express that will link up with Seaway. Downstream, we’re continuing to develop the Houston terminal opportunities. Since we acquired Ingleside, we’ve seen increasing interest on several fronts, which is already proving out the upside. On conventional, we’re progressing a 2 million-barrel storage expansion. The terminal is already permitted for 5, actually, so we can move that one along once we get commitments. There’s also potential emerging for NGL exports; stay tuned for more on that over the next while. As you saw today, we’re also now developing an integrated solution for blue hydrogen and ammonia production with Humble Oil. The key to this concept is the integrated value chain through to exports. Texas Eastern runs just north of Ingleside, so it's well positioned to provide feedstock for hydrogen. It looks like the geology in this region is suited for carbon capture storage. The hydrogen and ammonia production would meet local demand and the export market, which is booming. So, multiple upsides at Ingleside. Now to carbon capture in Alberta. In March, we were awarded the right to move forward on our Wabamun storage hub. We are now validating the geology. Another positive was the federal government’s investment tax credit, 50% on capture and 37.5% on transportation and storage. This will go a long way to help make the numbers work. With 4 megatons per year captured and potential upside over time, this project will be one of the largest globally. We’ve provided you a preliminary timeline, which could see the project in service as early as 2026. With our utility, population growth will drive new gas connections and expansion of transmission and storage. In fact, we just FID-ed an expansion of our Panhandle system. It’s a $300 million investment to support growing greenhouse and power demand markets in Ontario. The utility continues to generate about $1 billion to $1.5 billion of ratable annual investment, so it’s a great business and a real gem in our portfolio. Moving to renewables, we had a strong quarter, exceeding our resource target; that’s good to see. What we have in execution will drive visible EBITDA growth through 2024. In France, we have four offshore projects in construction, including our first floating facility. We’re installing turbines at Saint Nazaire, and we’re in the fabrication phase at Fécamp as well as preconstruction at Calvados and Provence Grand Large. In North America, we have 10 self-power projects in progress, seven of those are expected to enter this year. And remember, we can build these quicker since they’re inside the fence. We’re also moving along about 3 gigawatts of opportunity for the next phase of growth post-2024. Before I pass it over to Vern, as you heard, we’re seeing lots of positive fundamentals right now, and I’ve covered a variety of opportunities on both the conventional and low-carbon fronts. So, he’s going to remind you about our framework and discipline around putting free cash flow to work and maximizing value. Over to you, Vern.

Thank you, Al, and good morning, everyone. Our first quarter results were significantly up compared to 2021 on solid operational performance across all of our businesses. We benefited from the $14 billion of capital that we put to work last year. In liquids, the Mainline moved about 3 million barrels per day in Q1, up 9% year-over-year, taking advantage of the additional capacity from Line 3. As a reminder, until we finalize the tolling for the Mainline, we’ll be including a provision in our results for that segment. Our Ingleside facility with its highly contracted cash flow is performing as expected, and it should remain strong through the balance of the year. Gas transmission utilization was solid, and the $1.4 billion of expansion added to our B.C. Pipeline System last year is driving growth in EBITDA. It’s business as usual at the utility with customer growth and colder weather making positive contributions in the first quarter. In the quarter, our Renewables business benefited from higher wind resource availability. Energy Services continued to experience narrow basis differentials and backwardation in the quarter, resulting in below-expectation results. Finally, lower capitalization of interest expense associated with the Line 3 replacement has led to higher financing costs. So, it’s been a very solid start to the year. Let’s move over to our outlook. With the strong first quarter, we’re confident we’re on track to achieve our full-year guidance. Our systems are expected to continue to be highly utilized, including the Mainline, which is on track for an average of 2.95 million barrels per day for the year. As always, this factors in a seasonal decline in throughput in the second and third quarters due to upstream and downstream maintenance activity. Our exposure to rising commodity prices remains limited, though we expect some modest upside on Aux Sable and DCP. Gas Distribution and new Renewables are on track to meet their annual guidance. We’re expecting Energy Services results in Q2 to be comparable to Q1, presenting a slight headwind for the year. The outlook for Energy Services improves through 2023 and beyond as we have transportation and storage contracts expiring at the end of this year and early in 2023. We’re well protected against inflation. As a reminder, 80% of our revenue has some form of inflation protection through our various tolling mechanisms. Revenues are adjusted through regular rate filings or directly through embedded contractual inflation escalators. Our secured capital has been largely contracted for 2022, which provides good protection against capital cost increases, and we continue to manage our capital programs through active supply chain procurement and fixed-price EPC contracts. Our financing costs are also well protected. Although 90% of our debt is fixed-rate debt, minimizing our near-term exposure to rising interest rates, we continue to optimize our financing. We’re generating a lot of cash flow and more investment capacity. So, let’s move on to our capital allocation framework. Our priorities remain unchanged, and we’re making good progress in all areas. Our balance sheet is in great shape. We’re on track for debt-to-EBITDA to be at the low end of our target range by the end of the year. S&P and Fitch just reaffirmed our BBB high stable credit ratings. We have increased our dividend by 3% in 2022; that’s our 27th consecutive annual increase. We initiated our share buyback program. That’s the model going forward: ratable dividend growth supplemented where it makes sense with share buybacks. Our cash flow and balance sheet leave us with about $5 billion to $6 billion of annual investment capacity. We expect between $3 billion to $4 billion to be deployed to low-multiple organic expansions and system optimizations, along with utility rate base and modernization capital in gas transmission. That leaves about $2 billion per year available for more organic growth, asset acquisitions, share buybacks, or debt repayment. While we review all of these options as we move through the year to ensure that we continue to maximize shareholder returns, all of these options will need to meet our low-risk business model, exceed risk-adjusted hurdle rates, have a strong strategic fit, and align with our emission reduction goals. As always, we will continuously evaluate options to recycle capital where appropriate to supplement the $5 billion to $6 billion of annual investment capacity. Our secured capital continues to grow. Today, our secured capital program sits at just over $10 billion. These projects will support our 5% to 7% DCF per share growth outlook over our three-year planning horizon. The $10 billion in secured capital includes $1 billion that we announced so far in 2022. All of this secured capital is highly contracted or rate-regulated, which fits our low-risk commercial model. As you just heard, we’re advancing a number of exciting opportunities across all of our businesses. This will drive growth in 2024 and beyond. Before I turn it back to Al, let me spend a minute on how we’re advancing our ESG priorities. ESG is foundational to our business. Our goal is to maintain and enhance our ESG-leading position. We are embedding our ESG priorities into our compensation and how we finance our business. Our strategic plans and annual budgets incorporate strategies and capital expenditures needed to meet our emissions goals. We believe this differentiates us in our sector and better aligns us with all of our stakeholders, including customers, investors, communities, and many more. We’re making good progress on the emission targets we set in late 2020 and we continue to challenge ourselves to improve. In addition to our 2020 emission targets, earlier this year, we made some additional commitments. These include working with organizations to support the development of emissions reduction guidelines for our sector, engaging with our suppliers to generate further Scope 3 emission reductions, and providing more reporting on different net-zero scenarios. Our sustainability report, which will be issued in June, will provide more information on how emission reduction targets are factored into all of our capital investment decisions. It will provide further details on our biodiversity programs, greater transparency on our path to net-zero, and updates on our approach to indigenous reconciliation. In summary, we continue to raise the bar on how we approach ESG. With that, I’m going to turn it back to Al.

Thanks, Vern. A few takeaways to close. The energy crisis demonstrates once again that all sources of energy are needed to ensure affordable, reliable, and secure energy while achieving climate goals. North America is an ideal spot to be part of the solution, and Enbridge plays a key role. Our footprint, access to the best markets, combined with being ahead of the curve on low-carbon, puts us in an excellent position. Our strong balance sheet and differentiated approach to sustainability mean we’re a natural midstream partner to our upstream and downstream customers. Finally, we’ll continue to take a disciplined approach and not compromise our low-risk business model. Together, we think this provides a great opportunity to grow the business and a solid value proposition for our investors. I’ll now turn it back over to the operator for Q&A.

Thank you. We will now begin the question-and-answer session. Robert Kwan from RBC Capital Markets is on the line with the question.

Could you please elaborate on the capital allocation priorities for the $2 billion, especially in light of the changes in the environment such as energy security opportunities and energy transition, as well as the increase in share price? What are some of the factors that have shifted since you last discussed this during the previous quarterly call?

It’s a good question to start, Robert. Well, first of all, as you heard through those remarks, I think there’s been definitely a positive shift in the fundamentals. We certainly will see more in the hopper for sure. I think it’s probably too early to tell whether that changes the broader outlook. And you heard Vern’s comments about our capital allocation discipline. I think the way we’re looking at it at this point is there’s really no change to how we’re looking at allocation. Discipline will remain around the balance sheet, the dividend growth, and we’re going to continue to really make sure that we invest wisely. So, in a nutshell, I guess, a lot more opportunity, but we’ll continue to put a pretty strong filter on what we’re doing and comparing opportunities that we have to invest capital with each other. That's really how we look at it, Robert; no major change right now, but certainly more opportunity ahead.

Got it. I just was wondering as part of that, is there maybe a bit more of a bias to reducing debt effectively just for bringing up balance sheet capacity for new projects and a specific project? I'm interested to get your comment on is just, there’s a lot of stuff going on in B.C., as you highlighted, and especially that T-South expansion is pretty big. So, if Woodfibre goes ahead, just with growth in the LBC, do you have a sense, or can you provide some color as to whether you think supplies diversity is one of their goals, and therefore how’s your project positioned versus say something along the Southern crossing line, or do you see the potential for both of those projects to go ahead?

Yes. I think our project is definitely in a great position there, Robert, for a bunch of reasons, the main one has to do with the imperativeness of the coal, and that stems in large part from the scale of the system. The other part is, if you recall, the Westcoast system is more or less a north-south header. That gives us the opportunity to expand to the Westcoast, but also to continue volumes down south. As to the capital allocation implications there and the size of those projects, if you think about it, we’re throwing off, as Vern said, a lot of free cash flow right now, and we will continue to do that over the next two to three years. So, the projects that we’re talking about are certainly not cash-consuming in the next couple of years in any material way. So, in a way, to get back to your original point, you’re sort of building up some excess capacity here while those projects come to fruition in the next two, three, four years, capital spending-wise. As far as the balance sheet, Vern can expand on this, but essentially, we’re in good shape right now. I think, we’ve been pretty clear about the 4.5 to 5. We’ll be near the bottom of that range by the end of this year. It's possible that with free cash flow, we could pop below that 4.5 in the next little while as those larger projects come to fruition. So, we’ll be building up some capacity for that.

Just want to start off with the new Ingleside hydrogen ammonia initiative, as you outlined there. Just wondering if you could peel in a bit more, I guess, on what some of the drivers are that could help you reach a positive FID. Who are the end customers that you’re looking to service here? What type of contractual support are you expecting here? What type of timeline? Just more color on this would be helpful.

Okay. I’ll start, and then we’ll get Colin to provide some more details. This is a great example of how our pipe and facilities that are in place gives us an advantage. Broadly speaking in this region, we’ve got a big gas header along the Gulf. We’ve got Seaway, we’ve got Ingleside now, and a bunch of projects in development. We have pretty strong fundamental support here for exports; obviously, gas is critical. CCUS is essential so this has multiple attributes that contribute to the value chain I mentioned. We have a brownfield industrial complex here with some very big players. It's naturally helpful for us to grow from this area, and the business model should fit quite well with the ongoing demand. So, that’s the big picture here. There are sizable opportunities that can really move the needle. So, that’s the background in context of how we’re thinking about the region generally, but maybe Colin can provide some context around customers and markets specific to this opportunity.

Yes. Hey. Thanks, Al. Good morning, Jeremy. So, think about this project probably with a capital cost of $2 billion to $3 billion. We’re joint-venturing, so we have half of that. In terms of commercial construct, we’d like to term this out under a take-or-pay type arrangement. We’ll be jointly marketing the facilities with our partner, including European fertilizer companies, as well as domestic and European power generation with respect to hydrogen. The concept is pretty novel, exporting decarbonized fossil fuels. I think you’ll see more of these. The Ingleside facility has a 54-foot dredge depth now, ample space to build facilities, and is close to open water. So, that’s the formula and model we’re looking for here.

Thank you for that. I want to shift to the WCSB and the takeaway situation. We observe some mixed factors regarding egress. Trans Mountain is experiencing delays, and there are changes in Canadian government financing support. They still need to navigate through sensitive population areas, which presents challenges and uncertainty. However, even with oil prices at $100, we have not seen significant final investment decisions from the WCSB. Do you anticipate much growth from the basin and an increase in shipper demand for more capacity that could support a new CTS? If demand exceeds takeaway capacity, would that be a more favorable incentive? Or do you believe this demand will not materialize, and the basin will see limited growth, making a cost of service outcome more likely?

Okay. I’ll start again, Jeremy. The fundamentals here for the oil sands basin and the basins generally in Western Canada are pretty positive. I think we all know about the attributes around the size of reserves and the surety of getting those to the market. The upstream group has done a tremendous job both in terms of lowering cash costs and emissions. I think fundamentally, we’re very positive on that part. Producers are going to want to see some stability in their long-term plans, but they don’t need $100 oil for that to happen. However, they’re looking for clarity on longer-term pricing. They will be looking at capital-efficient solutions, debottlenecking first, as there are concerns about supply chains and of course, egress from the basin. We believe the Mainline is extremely well positioned for this. The Mainline tolling agreement will actually be important; we need clarity on the commercial underpinning for those projects that we have in the queue, which Colin can get to. But we need clarity in order to continue to incrementally expand. The basin primarily will likely be behind in its ability to react to the increasing prices due to the nature of what we’re talking about with oil sands—longer-dated investment profiles. That’s the bigger picture, Colin. Do you want to give some specifics around where we are on the expansion opportunities and the timing?

Yes. We’re keeping our Mainline expansion opportunities ready to go here and advancing long-lead items to enable them to move forward. We believe industry will continue to want some egress or insurance of egress having not had any for decades, and we’ll potentially weave that into any commercial arrangement we negotiate. The timing of those will have to be determined, but we’re keeping them warm.

I’ll just add one more thing here. Colin, you mentioned TMX, Jeremy. In the bigger picture here, if you think about it, we’ve got two nice pathways to the Gulf Coast, which will continue to be an extremely strong market. The thing that’s happened recently in terms of the security buffer that we’ve been talking about is our export position that relates to those two paths, which I think is ideal in terms of the longer-term future of heavy oil coming out of Western Canada. We know the Gulf Coast is a great destination and will continue to be, but we also have this additional opportunity to generate greater exports out of that region, which bodes well for us.

I want to circle back on the B.C. expansion projects. When you take a look at T-North, the first phase of the expansion, as well as the second phase of the expansion, specifically in the first phase, is that dependent on the T-South expansion and Woodfibre? Or could we see that progress independently just to serve LNG Canada demand?

I’ll go quickly, and then Cynthia will chime in. So on T-North, that goes ahead regardless. So, that’s the binding open season we’re talking about. On T-South, I think that is most probably dependent on Woodfibre LNG sanctioning. So that's the short answer. Cynthia, do you have anything to add there?

Yes. Thanks, Al. I think you covered it in your earlier remarks. We see the volumes that are currently assigned to Woodfibre serving the U.S. Pacific Northeast. So, when those 300 million cubes a day move to Woodfibre, we’re going to need to come in with some additional supplies. That’s why we’ll really have that opportunity to expand T-South when that happens.

Well, I think, again, I’ll go first. On the West, this is really the crux of the advantage in this case, whether you look at the community aspects of building your infrastructure and obviously the indigenous groups along the right of way. The fact that we’ve been there for so long, the fact that we have good relationships, and we’re not doing a lot of looping or twinning of pipelines. We’re in a pretty good position to expand the T-South system; that goes for T-North as well. Supply chain-wise, that’s something we’re going to manage. Everybody is exposed to increasing costs and inflation. It’s something we can manage. We’ve got a solid supply chain group that strategically looks at this and can bring the size of our company to bear in terms of base-loading particular contractors. I think we’re in reasonable shape these days.

Thanks. Good morning. On the Ingleside facility, I just wanted to get an update regarding the interest you’re seeing from customers to potentially export NGLs from this facility. It sounds like you’re getting some traction there. And if you did export NGLs, would you be looking to export LPGs or other NGL products? How much would you export and where would you source the NGLs from?

Colin, do you want to take that?

We’re looking at various forms of purity for NGL export out of Ingleside. I won’t be too specific, but we’d be sourcing them locally, obviously. And these are under development, so I think I’ll just leave it there for now.

Okay. Got it. And then, just staying in the U.S. So, gas production is increasing both in the Northeast and the Haynesville, and both regions have some egress constraints. Recognizing that you have pipelines in both areas, are you evaluating any potential projects to improve takeaway? Do you have the ability to do any brownfield expansions, or would they need to be greenfield at this point?

Yes. We obviously have our Texas Eastern system, which uniquely positions us to serve Haynesville production and get to the Gulf Coast markets with our existing infrastructure. There are some opportunities for both brownfield and greenfield in this space. We’re continuing to have those conversations with key players to figure out the best path forward to serve the incremental needs.

A lot has changed since we last spoke. I’m wondering if you can discuss if there’s been an understanding by policy makers, especially in the U.S. for the need to get permitting moving in order to build the infrastructure that’s required to deal with this energy crisis.

Let me put it this way, Rob. I think we’re certainly hearing the right things. They definitely get it. The impact on consumers, from home heating costs to prices at the pump, is something everyone understands very well. I’m not convinced yet that we’re going to see quick action to provide additional clarity on regulatory and permitting. They need to address a myriad of issues: general policy related to the acceleration of lower carbon opportunities, federal versus state jurisdictions, and a complex array of permitting approvals. We all know what needs to be done here, but I think we need a little bit of time for this to unfold. However, if there ever was a time, in terms of the signals being sent around the impact on consumers, this is it. We continue to work on this. All the people around this table here are engaging with governments and explaining what’s happening and what we need to see to put capital to work. We have the capital and the capability to navigate these regulatory processes, but we need more policy support at a very high level. Hopefully, that will come through. You have to be skilled in this area regardless of policy issues. Engagement, working with communities, and collaborating with indigenous groups are things that will help get projects moving.

First, I wanted to ask about the Mainline System in the context of changes in global flows of crude and the Russian production and exports on the crude side that currently seem to be rerouted, but there’s definitely some long-term uncertainty there, coupled with Mexico’s publicly expressed intention to consume more of their domestic production, which is heavy sour in nature. There does seem to be an incremental bid in the marketplace for that sour barrel. Are these structural themes affecting your discussions with shippers about the rate? How do you view these themes in light of the value and competitive advantage of your system? Not just the Mainline, but really Mid-Con all the way to the Gulf Coast?

This is a great question, Theresa. The short answer is that we're probably in a situation where it's too early to tell. There's no doubt that a price change is driven by different signals on supply. How Russian volumes are reabsorbed and how flows are realigned is still to be determined. However, we're in a strong position; Canada and the U.S., due to the integrated nature of our systems, are well-equipped to fill this gap. Energy demand in Europe and Asia will be competing for LNG, which is an important part of the conversation. It's still a bit early to determine how the flows will be realigned, but we are certainly in a good position. Regarding the Mainline, perhaps Colin can share his insights on that.

Yes. 45% is the market share position presently for Canadian crude in the Gulf, where it competes. This phenomenon has been alive for a while, and the points you’re making accentuate the competitiveness of Canadian crude, especially considering Venezuela has been a structural factor affecting supply to the Gulf. The Mainline feeds all that. We’re looking at another path down through Cushing as well, feeding this market phenomenon.

Thank you. Would you mind commenting on what is the latest cost estimate on the Line 5 tunnel, please?

Yes, we’re probably looking at about $750 million for the Line 5 tunnel, and it’s probably trending up.

Thank you. Just further with respect to Line 5, how do various policymakers and regulators understand the importance of keeping existing energy infrastructure used and useful? Can you give us a sense of the timeline to resolve various challenges along there and what some of the solutions might be to meet the needs of all holders?

I agree with your point, Linda. Policymakers all around, on both sides of the border, fully understand the importance of keeping existing infrastructure flowing, especially in light of recent global events. The Canadian government has been very supportive of all elements of Line 5 in both Michigan and Wisconsin. Comments made recently reflect that support. The timelines on both reroutes are multi-year, and we’re working through the permitting processes to push forward as prudently and thoroughly as possible.

It’s important to note that state governments in the regions of both Michigan and Wisconsin understand the criticality of this infrastructure to their states and consumers. This support has been beneficial as well.

Looking through your slides, there are several large projects ranging from $1 billion to $2 billion, and your guidance suggests it could exceed that. I’m curious if the $5 billion to $6 billion of capital expenditure you previously mentioned has the potential for upward movement, perhaps not reaching the $10 billion mark? It seems like there is substantial pent-up demand for your business to grow organically.

I’m going to get Vern to comment, but generally from my point of view, Ben, there may be potential for that number to rise. On the other hand, what’s important is how we filter any increments of growth and ensure that we maintain the discipline we’ve focused on over the last number of years. The opportunity pool may be larger, but we’ll be careful about how much we deploy, which has generally been constrained to the amount of free cash flow that we have to invest. Vern, do you want to add to that?

I think we discussed this extensively at our Investor Day in December. There’s really no change. The balance sheet remains our number one priority. The flexibility we maintain in all markets is critical for us. Our free cash flow generation and flexibility on our balance sheet gives us that $5 billion to $6 billion a year investment capacity. We’ll ensure we focus on the highest and most attractive projects first. If we have too many opportunities, that’s fortunate; some will not proceed.

Yes. We’re continuing to progress with Ridgeline. There will be an opportunity as we move forward. We’re still awaiting FID. If we get the FID as planned, that would target a Q4 2026 service date.

Maybe just a follow-up to some of the questions on the heavy oil coming out of Western Canada. It seems that the Mainline is progressing towards a tolling agreement in 2023. How should we think about the potential tolling agreement and the expansion of the Mainline? Are they interrelated or could the expansion ultimately be announced before the resolution?

Colin, do you want to deal with that?

Yes. They need to be sequenced together. We need clarity on the tolling agreement to understand how any expansions would work within that framework. That’s the order that needs to happen.

Additionally, one of the key things we're discussing with customers is the need for an underpinning for those expansions. We’re ready to go on these expansions, and it will be really important to provide some additional capacity given the opportunities we have in front of the basin, which we've discussed throughout the call; we’re in a positive position. So hopefully, we can move that tolling agreement along soon.

That's great. In terms of just the sequencing of events, could that also impact the Flanagan South and potential Seaway expansion in 2024? Or are those separate events, in your view?

Yes, these are likely in the same mix. As we just discussed, we need clarity on the tolling agreement, and that would affect how we approach the Flanagan South and Seaway expansions.

Makes sense. Lastly, I have a quick final question. Understanding the NGL situation and more details to come on that, could you just discuss how relationships with DCP and PSX, along with the new cracker in the region, could ultimately drive success for the projects? Are you considering partnering on the NGL projects?

This is back to you, Colin.

Yes. We have a strong relationship with the parties you mentioned, and they will be involved here.

We have reached our time limit and are not able to take any further questions at this time. I will now turn the call over to Jonathan Morgan for final remarks. Okay, great. Thank you, everyone, for joining us this morning. We appreciate your ongoing interest in Enbridge. As always, our Investor Relations team is available following the call to address any additional questions you may have. So, once again, thank you, and have a great day.

This concludes today’s conference call. Thank you for participating. You may now disconnect. Thank you.